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Collaborating Authors
South China Sea
This article, written by Dennis Denney, contains highlights of paper IPTC 17091, โExtending Mature-Well Life by Innovative Slurry Design and Complex Coiled-Tubing Well Work,โ by M. Hairi A. Razak, Aulfah Azman, SPE, and Haryat Timan, Petronas, and M. Heikal Kasim, SPE, and M. Fakhrurazi Ishak, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A well in the South China Sea was diagnosed by ultrasonic and temperature logging to have a well-integrity problem, forcing the operator to shut in the well because the leak created a high tubing/casing-annulus pressure. Through-tubing well work was used because it is more economical than a full workover, particularly for wells in a mature field with depleted reserves. Enhanced and optimized cement slurry was engineered with a well-work approach that specified acoustic fluid-level monitoring. The packer leak was repaired successfully. Introduction This oil and gas field is 260 km from Kerteh, Malaysia. Discovered in 1971, first oil production was in 1978. The field is in the southeastern part of the Malay basin at an average water depth of 70 m. The field contains both gas and oilย reservoirs. In August 2002, communication was observed between the production casing and tubing of the subject well, indicating a leaking production packer. Four major attempts to correct the problem were conducted, all unsuccessful. The first attempt was in February 2003 by bullheading calcium carbonate (CaCO3) into the annulus. This procedure was attempted again in May 2003. In August 2007, a coiled-tubing (CT) unit was used to spot cement inside the production tubing and displace it into the annulus through a gas lift mandrel to the top of the packer. Another cementing job was attempted in December 2008, through the same gas lift mandrel. Diagnosis Lessons learned from the first cementing failure, in 2007, were used to design the attempt in 2008. Even though job execution was smooth in the field, several mistakes occurred that were not realized by the team during the job-design process. The experiences of those cementing attempts helped mature the subsequent design and decisions, ensuring success for future packer-cementing jobs in peninsular Malaysia operations. Cement-Slurry Design. CT-cementing procedures are different from those of conventional/primary cementing from a rig, with the biggest difference being the need for batch mixing for CT cementing vs. on-the-fly mixing for primary cementing. Batch mixing requires higher mixing energy compared with primary cementing, with an additional mixing energy to pump the cement slurry through the CT relative to pumping down the casing. The higher mixing energy decreases thickening time (TT) such that the cement slurry has potential to accidentally set inside the CT, thereby requiring a suitable retarder to prolong the TT.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 156888, โDemonstrating the Value of Integrating FPWD Measurements With Managed-Pressure Drilling To Drill Narrow Mud-Weight Windows Safely in an HP/HT Environment,โ by L. Umar, SPE, I. Azian, N. Azree, and A.R.M. Ali, Petronas, and A. Waguih, SPE, F. Rojas, SPE, S. Fey, SPE, B. Subroto, SPE, B. Dow, and G. Garcia, SPE, Schlumberger, prepared for the 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Milan, Italy, 20-21 March. The paper has not been peer reviewed. A high-pressure/high-temperature (HP/HT) exploration field in Block PM on the northern side of the Malay basin, Malaysia, is notorious for a steeply rising pressure ramp, narrow drilling-operation window (only 0.5 to 0.6 lbm/gal in the 14ยพ and 9ยฝ-in. sections), and interbedded sand/coal and shale formations. Block PM is still in the exploration-and-appraisal stage; therefore, petrophysical information is limited. Well SBD-2 was the second attempt to reach and cross the F and H sands. Formation-pressure-while-drilling (FPWD) and managed-pressure-drilling (MPD) technologies were applied to drill this well. FPWD provided a direct pressure measurement while drilling to set the lower boundary, and formation-integrity tests (FITs) with MPD provided the upper boundary. Introduction The SB field has a relatively high temperature gradient and abnormal-pressure regimes. Challenges in this HP/HT environment include a reduced kick tolerance, narrow drilling margin, higher drilling-fluid densities, high temperature (limitations in formation-evaluation equipment), wellbore ballooning, and availability of personnel experienced in HP/HT drilling. Well SBD-2 had been considered undrillable because of its very narrow safe-drilling margin. The previous attempt to drill through the F and H reservoir sands, Well SBD-1, suffered an influx from the formation that exceeded kick tolerance and compromised the fracture gradient, resulting in total fluid losses. Well SBD-1 failed to reach total depth (TD) despite the use of an MPD systemโ200 m shy of the geologic target. Well SBD-2 was drilled only 50 m away from Well SBD-1. Given the close proximity, there were offset pressure data for planning Well SBD-2 down to a depth of X240 m, but beyond this depth it would be exploratory drilling. Given the uncertainties that would be encountered drilling past X240 m, the engineering team sought best practices and technologies that would provide the greatest chance of success drilling into such a tight margin at high temperature. The 8ยฝร9ยฝ-in. reservoir section would use an automated MPD system to mitigate drilling risk complemented by an FPWD tool in the drilling bottomhole assembly (BHA) to provide direct pressure measurements. The MPD sys-tem was used for early kick detection (EKD), FITs, dynamic flow checks, and constant-bottomhole-pressure (CBHP) control for a safe mud-weight window that was expected to be less than 0.9 lbm/gal. The high mud weight needed to drill this formation resulted in a high equivalent circulating density (ECD) throughout the section, requiring the MPD system to maintain a static condition between 0.2 and 0.4 lbm/gal. The FPWD tool would provide pressure data to establish the lower limit for the MPD fingerprint tests, and to serve as calibration points for the pore-pressure model. The objective in this 8ยฝร9ยฝ-in. section was to maintain overbalance in the narrow window between pore pressure and fracture gradient. These tight drilling margins required use of an automated MPD system with software capable of predicting temperature effects and annular-pressure behavior during any well-controlย situation.
- Europe > Italy > Lombardy > Milan > Milan (0.24)
- Asia > Middle East > UAE > Abu Dhabi Emirate (0.24)
- Asia > Malaysia > South China Sea (0.24)
- Geology > Geological Subdiscipline > Geomechanics (0.73)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Asab Field > Thamama Group Formation (0.99)
- Asia > Malaysia > South China Sea > Malay Basin (0.99)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139932, โDrilling Highly Depleted Formations With Engineered- Particle Nonaqueous Fluids: South China Sea,โ by Michael R. Niznik, SPE, Adela Lawrence, SPE, and Sabine C. Zeilinger, SPE, ExxonMobil, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. A new engineered-particle nonaqueous-fluid (EP-NAF) system was used in the Malay basin of the South China Sea to drill through highly depleted sands at elevated densities. The fluid contains sized particles to bridge and prop open fractures as they occur during actual drilling operations. Formation integrity is gained immediately and does not require additional critical-path rig time.ย Background and Well-Design Overview The Malay basin in the South China Sea contains multiple oil and gas accumulations, some of which have been on production for several decades. Many of these mature fields have economically recoverable quantities of hydrocarbons but are challenging because depleted zones are adjacent to formations prone to wellbore instability. A four-well infill development program was planned in one of these mature fields. The field is 200 km offshore in 70 m of water. Several platforms were installed to develop the field, which has been producing for more than 20 years. Typically, tender-assisted platform rigs are used in this field. Well-Design Challenges and Planning All proposed wells would be side-tracked from existing donor wellbores. A variety of casing sizes was used in the donors, and exact cement tops were not known. The exact sidetrack point was engineered to take into account collision avoidance of offset wells, cement behind casing, formations in which to sidetrack, and dogleg requirements to meet geology and reservoir objectives. The target reservoir was the Group-J sands that lie below the Group-I reservoir, which was completed and put on production more than 20 years earlier. The pore pressure of the Group-I reservoir in the area where the proposed wells would penetrate was determined to be depleted to a 3.7-lbm/gal gradient. The target Group-J sands also were slightly depleted to a 6.8-lbm/gal gradient because of production in adjacent fault blocks. The targeted Group-J reservoir has lower-permeability sands compared with the Group-I reservoir above it. Horizontal wells were planned to intersect additional reservoir footage and to maximize productivity and reserves recovery. The Group-J sands are highly consolidated, and modeling, along with offset-well analysis, determined that sand control would not be required. The wells could be completed open hole with predrilled liners, which minimized completion complexity and cost.
- Asia > China (1.00)
- Asia > Malaysia > South China Sea (0.45)
- Europe > Netherlands > North Holland > Amsterdam (0.24)
- North America > United States > Texas > Dawson County (0.24)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drilling Operations (1.00)
- (5 more...)
This article is a synopsis of paper SPE 64740, "Improving the Static Model of a Complex Reservoir Through the Inversion of Seismic Data," by Zakaria B. Marzuki, SPE, Petronas Carigali Sdn. Bhd., and Mark S. Sams and Dave Atkins, Jason Geosystems Asia, originally presented at the 2000 SPE International Oil and Gas Conference and Exhibition in China, Beijing, 7-10 November.
- Geology > Geological Subdiscipline > Stratigraphy (0.49)
- Geology > Rock Type (0.39)
Research & Scientific Services participated blocks by a north-south trending fault system. Interpretation of hydrocarbon-saturated in a joint research project on seismically Although more than 100 exploration sands vs. water-bearing shales in the seismic integrated reservoir modeling involving and development wells penetrate the east data was aided by the presence of a the Guntong field, Malay basin. By fields that require fast-track development wells had been drilled in the west fault use of the predictive relationship, porosity and are still in the early development block when this study was initiated. This values were assigned to each segment of all stage, the availability of three-dimensional study focused on three reservoir intervals seismic traces within the study interval. Each zone Geostatistical methods were used to build carry through to flow-simulation studies represents a gridded volume of genetically 3D models of sand percent, porosity, and and affect estimates of reserves and reservoir related reservoir or nonreservoir rock.
- Asia > Malaysia > Terengganu > South China Sea (0.28)
- Asia > Malaysia > South China Sea (0.26)
- Asia > Turkmenistan > Lebap Region (0.25)
- Geology > Rock Type (0.38)
- Geology > Structural Geology > Fault (0.37)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Guntong Field (0.99)
- Asia > Malaysia > South China Sea > Malay Basin (0.99)